CA2932090A1 - System and method for heating a bitumen or heavy oil reservoir - Google Patents

Abstract

A method for heating a bitumen reservoir is provided. Heated liquid phase heat transfer fluid is circulated within a well in the bitumen reservoir, wherein a second tubing is landed in a first tubing located within the well. The first tubing extends beyond the second tubing is being blocked at a distal end downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing. The second tubing is insulated with at least one portion thereof that is uninsulated.

Description

SYSTEM AND METHOD FOR HEATING A BITUMEN OR HEAVY OIL RESERVOIR
TECHNICAL FIELD
[0001] The following relates to systems and methods for heating a bitumen or heavy oil reservoir.
DESCRIPTION OF THE RELATED ART

[0002] Bitumen is known to be considerably viscous, does not flow like conventional crude oil, and can be present in an oil sand reservoir. As such, bitumen is recovered using what are considered non-conventional methods. For example, bitumen reservoirs are typically extracted from a geographical area using either surface mining techniques, wherein overburden is removed to access the underlying pay (e.g., oil sand ore-containing bitumen) and transported to an extraction facility; or using in situ techniques, wherein subsurface formations (containing the pay) are heated such that the bitumen is caused to flow into one or more wells drilled into the pay while leaving formation rock in the reservoir in place. Both surface mining and in situ processes produce a bitumen product that is subsequently sent to an upgrading and refining facility, to be refined into one or more petroleum products, such as gasoline and jet fuel.

[0003] Bitumen reservoirs that are too deep to feasibly permit bitumen recovery by mining techniques are typically accessed by drilling wellbores into the hydrocarbon bearing formation (i.e. the pay) and implementing an in situ technology. There are various in situ technologies available, such as steam driven based techniques. These include, for example, Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS). In a typical implementation of the SAGD method, a pair of horizontally oriented wells are drilled into the bitumen reservoir, such that the pair of horizontal wells are vertically aligned with respect to each other and separated by a relatively small distance, typically in the order of several meters. The well installed closer to the surface and above the other well is generally referred to as an injector well, and the well positioned below the injector well is referred to as a producer well. The injector well and the producer well are then connected to various equipment installed at a surface site.

[0004] Prior to extracting bitumen from the reservoir using the SAGD
method, "start-up" of the wells is generally required. As used herein, "start-up" generally refers to the step of achieving or enabling fluid communication between two or more wells situated in a bitumen reservoir. In a typical SAGD implementation, start-up is conventionally achieved by injecting and circulating steam through both the injector well and the producer well. The steam is circulated - -22933944.1 through both wells until the region between the injector well and the producer well (i.e. the inter-well region) has been sufficiently heated to mobilize the bitumen and therefore allow fluid communication between the wells. Once start-up has been achieved, production can begin.
During production, steam is typically introduced into the bitumen reservoir through the injector well which, in the process of condensing, further heats up the surrounding bitumen to lower its viscosity. The heated bitumen and the condensate then flows towards the producer well due to gravity, and are then pumped to the surface through the producer well.

[0005] However, achieving start-up using the conventional method of steam circulation can be inefficient and/or impractical for some bitumen reservoirs. For example, steam has been found to not effectively penetrate the cold bitumen surrounding the wells in low permeability formations or reservoirs (e.g. inclined heterolithic strata units). This can result in long start-up time and relatively high cost in achieving start-up if steam is employed as the primary heat source during the start-up phase of such low permeability reservoirs.
Moreover, steam circulation can result in poor conformance of the steam chamber due to such poor geology.
Furthermore, the conventional start-up method of steam circulation requires the surface equipment to be installed on-site for steam generation, which can unfavourably delay start-up in some cases.
SUMMARY

[0006] In one aspect, there is provided a method for heating a bitumen or heavy oil reservoir comprising circulating heated liquid phase heat transfer fluid within a well in the reservoir, wherein a second tubing is landed in a first tubing located within the well, the first tubing extending beyond the second tubing and being blocked at a distal end downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing, wherein the second tubing is insulated with at least one portion thereof that is uninsulated.

[0007] In an implementation of the method, at least a portion of at least one of the first and second tubing are insulated. The insulation can be provided at least along a generally vertical portion of the tubing. The insulation can also be provided along the entire length of the second tubing, with or without a plurality of ports provided along a generally horizontal portion of the second tubing to improve heat transfer evenly to the outer tubing and thereby the formation.

[0008] In an implementation of the method, the heat transfer fluid heats an interwell region between the well and another well, spaced vertically therefrom. The well can be an injector well 22933944.1 and the other well a producer well located below the injector well. The heat transfer fluid can also be circulated in the producer well.

[0009] In an implementation of the method, the method comprises deploying an obstruction mechanism into the first tubing prior to circulating the heat transfer fluid to block the first tubing ahead of the second tubing. The obstruction mechanism can comprise a bridge plug, rupture disk, or a bullnose attachment that can be punctured. In an implementation of the method, the method also comprises unblocking the first tubing when preheating has completed, for example, by either removing the obstruction or breaking the barrier created thereby.

[0010] In an implementation of the method, the heat transfer fluid is formulated from a base oil to resist oxidation and increases in viscosity. The heat transfer fluid can be of a type that exhibits a consistent heat capacity over a range of temperatures used during circulation. The heat transfer fluid, in an implementation, is heated to a temperature of approximately 250 degrees Celsius or greater.

[0011] In an implementation of the method, a fluid heating system used to heat the heat transfer fluid is assembled on a movable module located at a first site near the well, the method further comprising moving the movable module to a second site comprising at least one other well.

[0012] In an implementation of the method, the second tubing comprises coiled tubing.

[0013] In an implementation of the method, the well is used for a steam assisted gravity drainage (SAGD) bitumen recovery process, and wherein the first tubing corresponds to long tubing. In such an implementation , the well can be an injector well configured to inject steam into the bitumen or heavy oil reservoir using at least the long tubing, or can be a producer well configured to recover mobilized bitumen from the bitumen reservoir using at least the long tubing.

[0014] In an implementation, the method can comprise reheating cooled heat transfer fluid circulated to surface and repeating the method using at least a portion of reheated heat transfer fluid.

[0015] In an implementation of the method, an additional fluid can be injected into the well while the heat transfer fluid is being circulated. The additional fluid can be the same or different than the heat transfer fluid. The additional fluid can be injected during a pre-heating phase, during a production phase, and/or a start-up phase.

22933944.1

[0016] In an implementation of the method, the heat transfer fluid can be circulated at least in part using a pump or artificial lift mechanism installed in the first tubing.

[0017] In an implementation of the method, a vertical portion of the first tubing is insulated.
In an implementation of the method, the well is any one of a vertical well, an inf ill well, a step-out well, a multilateral well, or a branched well. The heated fluid can also be circulated to inhibit or reduce formation of hydrates or wax, or both, in the well.

[0018] In another aspect, there is provided a method for heating a bitumen or heavy oil reservoir comprising circulating heated liquid phase heat transfer fluid within a well in the reservoir, wherein a second tubing is landed in a first tubing located within the well, the first tubing extending beyond the second tubing and being blocked at a distal end downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing; and injecting an additional fluid into the bitumen reservoir via the well while circulating the heat transfer fluid.

[0019] In an implementation, the additional fluid can be injected through an annulus in the well that at least in part surrounds the first tubing. The additional fluid can be the same or different than the heat transfer fluid. The additional fluid can be injected during a pre-heating phase, during a production phase, and/or a start-up phase. The additional fluid can be injected intermittently or continuously.

[0020] In another aspect, there is provided a method for heating an interwell region between a first well positioned above a second well in a bitumen or heavy oil reservoir comprising circulating heated liquid phase heat transfer fluid within at least one of the first and second wells in the reservoir, wherein a second tubing is landed in a first tubing located within the at least one of the wells, the first tubing extending beyond the second tubing and being blocked at a distal end downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing, wherein the second tubing is insulated with at least one portion thereof that is uninsulated.

[0021] In an implementation, the heat transfer fluid is circulated within both the first and second wells. The interwell region can be heated using the heat transfer fluid until reaching fluid communication between the first and second wells, or can include subsequently injecting steam into the bitumen reservoir to achieve same. In an implementation of the method, the 22933944.1 method can include entering a production phase, which can include injecting steam, one or more solvents, etc.

[0022] In another aspect, there is provided a system for heating a bitumen or heavy oil reservoir comprising a source of heated liquid phase heat transfer fluid; a first tubing located within a well; a second tubing landed in the first tubing, the first tubing extending beyond the second tubing; and an obstruction mechanism deployed at a distal end of the first tubing downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing, wherein the second tubing is insulated with at least one portion thereof that is uninsulated.

[0023] In an implementation of the system, at least a portion of at least one of the first and second tubing are insulated. The insulation can be provided at least along a generally vertical portion of the tubing. The insulation can also be provided along the entire length of the second tubing, with a plurality of ports provided along a generally horizontal portion of the second tubing.

[0024] In yet another aspect, there is provided a system for heating a bitumen or heavy oil reservoir comprising: a source of heated liquid phase heat transfer fluid; a first tubing located within a well; a second tubing landed in the first tubing, the first tubing extending beyond the second tubing; an obstruction mechanism deployed at a distal end of the first tubing downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing; and equipment for injecting an additional fluid into the bitumen reservoir via the well while circulating the heat transfer fluid.

[0025] In yet another aspect, there is provided a system for heating an interwell region between a first well positioned above a second well in a bitumen or heavy oil reservoir comprising: a source of heated liquid phase heat transfer fluid; a first tubing located within at least one of the first and second wells; a second tubing landed in the first tubing, the first tubing extending beyond the second tubing; an obstruction mechanism deployed at a distal end of the first tubing downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing; and equipment for injecting an additional fluid into the bitumen reservoir via the well while circulating the heat transfer fluid.

22933944.1

[0026] The methods and systems can be used to provide a pre-heating phase that can be used before (or in some implementations instead of) a steam or solvent circulation process normally referred to as a "start-up" phase. The pre-heating phase is used in order to heat the area surrounding the well to at least reduce the amount of time required to complete the circulation or start-up phase, and to reduce the amount of steam, solvent or other fluid used for same. The method and system can also be used during a subsequent production phase, by keeping the second tubing in the first tubing.
BRIEF DESCRIPTION OF THE DRAWINGS

[0027] Embodiments will now be described by way of example only with reference to the appended drawings wherein:

[0028] FIG. 1 is a schematic block diagram of a heated fluid circulation system for heating a bitumen or heavy oil reservoir surrounding wells in the reservoir;

[0029] FIG. 2 is a schematic block diagram of a heated fluid circulation system adapted for pre-heating from multiple wells in a bitumen or heavy oil reservoir;

[0030] FIG. 3 is a schematic block diagram of a heated fluid circulation system adapted for pre-heating from a production well and from an injection well in a SAGD
application;

[0031] FIG. 4A is a cross-sectional schematic view of a well in a bitumen reservoir during a pre-heating phase;

[0032] FIG. 4B is a cross-sectional schematic view of a well in a bitumen or heavy oil reservoir during a pre-heating phase;

[0033] FIG. 4C is a cross-sectional schematic view of a well in a bitumen or heavy oil reservoir during a pre-heating phase;

[0034] FIG. 5A is a cross-sectional schematic view of a well in a bitumen or heavy oil reservoir that utilizes a heated fluid circulation system while injecting another fluid;

[0035] FIG. 5B is a cross-sectional schematic view of a well in a bitumen or heavy oil reservoir that utilizes a heated fluid circulation system with a downhole pump;

[0036] FIG. 6 is a cross-sectional schematic view of a bullnose obstruction for containing heated fluid in long tubing;

[0037] FIG. 7 is a flow chart illustrating operations that can be implemented in setting up a heated fluid circulation system for pre-heating wells in a bitumen or heavy oil reservoir; and 22933944.1

[0038] FIG. 8 is a flow chart illustrating operations that can be implemented in utilizing a heated fluid circulation system for pre-heating wells in a bitumen or heavy oil reservoir.
DETAILED DESCRIPTION

[0039] A system for heating a bitumen or heavy oil reservoir is described herein that can be used before (or in some implementations instead of) a steam circulation or bullheading process normally referred to as a "start-up" phase, as well as during production subsequent to preheating and/or start-up. The pre-heating phase is used in order to heat the area surrounding the well to at least reduce the amount of time required to complete the circulation or start-up phase, and reduce the amount of steam or solvent required for same. For example, in a typical SAGD start-up, fluid communication is achieved in the area between the wells by heating that area using steam circulation or bullheading. Similarly, a solvent-based advanced oil recovery process can require at least some pre-heating before the solvents used can become effective.
When using steam circulation to achieve start-up, the steam facilities are required to be installed at the surface prior to commencing the start-up phase, which limits how early this process can begin. For example, it can be multiple years between drilling a well and the installation of the steam facilities. Moreover, circulating steam can be time consuming, typically requires continual supervision on-site due to operational considerations such as pressure spikes and so-called "steam hammer", uses facilities that are significant in size and cost, and increases the amount of water used in the oil recovery process.

[0040] The system described herein can advantageously enable earlier pre-heating of a bitumen reservoir surrounding a well pair to at least reduce the amount of steam circulation required, or remove the requirement of steam at all, e.g., in solvent based recovery processes.
The system can also be assembled on a moveable module or skid that can be moved off-site once the pre-heating phase is completed, and relocated to another site where needed, providing portability. . Pre-heating using a mobile heated fluid module can therefore occur prior to the steam generation facilities at surface being completed, which means that at least some warming of the interwell region can be achieved during an otherwise idle or "dead"
period.

[0041] In the following, there are provided a system and method for heating wells in a bitumen or heavy oil reservoir. The system and method can be operated to eliminate at least a portion of the steam circulation required during a start-up process, prior to commencing production, by pre-heating the wells. Pre-heating can be implemented by circulating heated fluid through injection tubing (e.g. coiled tubing, which can be insulated along at least a portion thereof) deployed in a long tubing installed in a well. The long tubing is of larger diameter than 22933944.1 the injection tubing so as to provide an annulus within the long tubing and outside of the injection tubing to enable circulation of the heated fluid. The long tubing can extend up to the entire length of the well, and may be accompanied by short tubing along a substantially vertical portion thereof. The long tubing and/or the short tubing in the well can also be insulated, along at least a portion thereof, preferably at least along the vertical portion(s).
The heated fluid can be a heat transfer fluid in a liquid phase, that is continuously circulated in order to conduct heat into the surrounding formation. An obstruction such as a bridge plug or packer is deployed into the long tubing to enable the heat transfer fluid to return to surface up the annulus between the outer surface of the injection tubing and the inner surface of the long tubing. By containing the heated fluid in this way, by circulation within a nested closed loop, the heated fluid is not lost to the reservoir, and can be re-heated and recycled within the system.

[0042] It can be appreciated that the principles discussed herein can equally apply to preheating any wells having a first tubing extending within the well, that can be obstructed ahead of a second tubing extending within the first tubing, which has been landed behind the obstruction to create a closed circulation system. That is, the second tubing is nested within the first tubing, and the nesting can be concentric or not.

[0043] In an implementation of the system and method, the same system is adapted for circulating heat transfer fluid in multiple wells, in multiple branches of a multilateral well, or in or between multiple well pairs.

[0044] In another implementation of the system and method, the system is adapted to pre-heat the reservoir adjacent to both injector and producer wells in a SAGD well pair, and into the interwell region.

[0045] In another implementation, the system and method are used during an advanced oil recovery process (e.g., SAGD, solvent process, etc.) subsequent to a pre-heating phase. That is, the system and method described herein can be used during any one or more of a pre-heating phase, a start-up phase, and a production phase to be a primary source of heat.
Further, the system can also or instead be used to enhance or maintain the primary source of heat to the well, such as when heat is provided to the well primarily by injection of a heated fluid.
Typically, this would involve the injection of steam, water, solvent, or other fluids into the well, and the system described herein can be used to heat such injected fluid.

[0046] Turning now to the figures, FIG. 1 illustrates a bitumen or heavy oil reservoir, hereinafter referred to as the "pay 10"; which is accessed for in situ recovery using one or more 22933944.1 wells 16. The pay 10 underlies a layer of overburden 12 between the pay 10 and the surface 14. The one or more wells 16 are drilled from the surface 14 down into the pay 10 as is known in the art. The number and position of the wells 16 is dictated by the particular advanced oil recovery process being used, e.g., SAGD, CSS, solvent-based recovery, etc.
FIG. 1 includes a single well 16 with generally vertical and horizontal portions for ease of illustration, however, as discussed below, the principles discussed herein equally apply to multiple-well configurations, for example a SAGD well pair (see FIG. 3). It can be appreciated that the well configuration shown in FIG. 1 is for illustrative purposes only. For example, in some implementations, the wells 16 are drilled into the overburden 12 at an angle rather than substantially vertically or horizontally. Other well configurations, include vertical wells (for both bitumen and conventional oil, including off-shore operations), inf ill or step-out wells, multilateral or branched wells, etc.
The principles described herein therefore equally apply to such different well configurations.

[0047] A
fluid heating system 20 is fluidly coupled to the well 16. The fluid heating system 20 includes a fluid supply 22 (stored in a thermally rated expansion tank), one or more pumps 26 for drawing fluid from the fluid supply 22, and one or more fluid heaters 24 for heating the fluid to generate heated fluid 30. The fluid heating system 20 can be assembled on a movable platform, rig or "module" 28 to enable the system 20 to be moved to another site where needed, for example, after the pre-heating phase is completed if the heating system 20 is not needed during later phases of well operation. The pumps 26 are used to provide the fluid to the fluid heaters 24 to generate heated fluid 30 to be transported in to the well 30 to pre-heat the pay 10 surrounding the well 16, as explained below. The fluid 30 is heated by the fluid heaters 24 which is provided by the pumps 26. The fluid 30 is a heat transfer fluid that is maintained in a liquid phase, and remains stable through a range of operating temperatures.
The fluid 30 can be formulated from a base oil such that it is resistant to oxidation and oxidative breakdown, as well as resistant to increases in viscosity as a result of such oxidation. The fluid 30 can also be formulated to exhibit a consistent heat capacity and thermal conductivity over the range of temperatures used during circulation, in order to maintain consistent heat transfer into the formation. Fluids 30 with these properties have been found to be stable at relatively high temperatures, e.g., greater than 300 degrees Celsius. Temperatures of, for example, 250 degrees Celsius or greater can be used. Various fluid types can be used as the heated fluid 30, for example, Calf lo produced by Petro-Canada which, in addition to the above properties, is found to leave minimal deposits and be relatively stable at high temperatures, namely those greater than 300 degrees Celsius. Calf lo is made from a hydro-treated mineral oil in which bonds are saturated to make the oil more stable and resistant to oxidation.
Other liquid-phase 22933944.1 heat transfer fluids can also be used according to the principles described herein, for example, synthetic oils such as polyalphaolef ins, glycol, aromatics, light crude oil, produced emulsion, water, a molten salt (e.g., one able to reach temperatures of > 500 degrees C), etc. The heated fluid 30 can also be modified to include additives, such as anticorrosive or antifouling agents, any additive to improve thermal stability of the fluid, nanoparticles, hydrocarbons, water, non-condensable gas (i.e. to act as a pushing agent to accelerate well communication), foaming agents, surfactants, etc.

[0048] Unheated fluid is drawn from the fluid supply 22 by the pump(s) 26.
The heated fluid 30 transfers some of its heat to the well 16 and the surrounding pay 10 and a stream of partially cooled fluid 32 is pumped back to surface 14. The heater 24 can be natural gas powered, which can be cost effective and more efficient than using steam circulation for pre-heating the wells 16. When available, pumping capabilities downhole can also be used to circulate the heated fluid 30 as herein described.

[0049] The heat transfer fluid 30 and the system described herein can be used to address other issues in a well 16. For example, in processes having a gas, water, low temperature, and high pressure, crystalline structures called hydrates can form in the well 16.
These "ice-like"
structures can cause several operational problems and safety hazards due to system pressurization. The pressure and temperature conditions can change particularly at valves or other locations where pressure changes are experienced, as well as temperature fluctuations.
Wax formation is another example of an operational problem that can be addressed using the heating system 20 described herein. That is, the heating system 20 can be used to prevent or at least inhibit or reduce the formation of hydrates and/or wax in a well 16 by increasing the temperature in particular regions where this condition is experienced.
Furthermore, the system 20 can be used during a production phase to convert water into steam downhole, resulting in an artificial lift system, potentially replacing downhole pumps or the use of a gas lift. As such, it can be appreciated that the heating system 20 described herein can be used in any application where circulating heat in a well, during any stage of an oil recovery process is desired. Lean zones can also benefit from hot oil circulation.

[0050] It can also be appreciated that the system 20 described herein can be used to remove heat from the well area, e.g., if heating was too excessive, by flowing heat transfer fluid 30 that is at a lower temperature than its surroundings.

[0051] As shown in FIG. 1, the well in this example implementation includes a generally vertical portion 34 extending from surface 14 towards the pay 10, and a generally horizontal 22933944.1 portion 36 that extends along the pay 10 above an underlying formation. A
"heel" portion 38 transitions the well 16 from the vertical portion 34 to the horizontal portion 36 and a "toe" portion 40 terminates the well 16 at the distal end of the horizontal portion 36. The well 16 shown in FIG. 1 herein represents various types of wells to which heating can be applied using the heated fluid 30, including SAGD or CSS wells, infill or step-out wells, wells used for solvent injection, wells heated by electric heating, etc. The portions of the well 16 shown in FIG. 1 can be formed by installing a casing within a wellbore drilled into the overburden 12 and the pay 10 as is known in the art.

[0052] FIG.
2 illustrates that the fluid heating system 20 can be adapted to service multiple wells or multiple branches of the same well, for energy integration, by providing a series of heated fluid source lines 30a, 30b, 30c, etc. and a series of return lines 32a, 32b, 32c entering and exiting a series of generally vertical portions 34a, 34b, 34c, of corresponding wells 16a, 16b, 16c, etc. It can be appreciated that any suitable fluid flow configuration can be used, including separate pumps 26 for each well 16, a single pump providing heated fluid 30 to branches of the same source line, etc. Similarly, the return lines can be arranged in any suitable manner to enable partially cooled fluid to be returned to the fluid supply 22 and pump(s) 26, or fluid heaters 24 for reheating purposes.

[0053] FIG.
3 illustrates a specific multi-well configuration for the fluid heating system 20 in which a pair of SAGD wells 15, 17 is preheated. In this example, an injector well 17 is located above a producer well 15. The producer well 15 includes a generally vertical portion 34a, a generally horizontal portion 36a, a heel portion 38a, and a toe portion 40a.
The injector well 17 includes a generally vertical portion 34b, a generally horizontal portion 36b, a heel portion 38b, and a toe portion 40b. The producer well 15 is heated using a first fluid source line 30a and first return line 32a and the injector well 17 is heated using a second fluid source line 30b and a second return line 32b. Since in prior configurations, steam can be circulated to pre-heat the formation 10 from both the injector well 17 and producer well 15, the fluid heating system 20 is particularly advantageous for use in pre-heating both wells in a SAGD well pair 15, 17 using the heated fluid 30 and fluid heating system 20 described herein.

[0054] The SAGD production site is positioned to allow one or more SAGD well-pairs 15,17 to be drilled from the surface 14 towards the bitumen reservoir (i.e., the pay 10). In the illustrated example, the injector well 17 is positioned above the producer well 15. As will be appreciated, during SAGD production, which is subsequent to the pre-heating phase, the injector well 17 is configured to inject steam into the pay 10 and the producer well 15 is 22933944.1 configured to recover a bitumen-containing fluid that has been mobilized by the injected steam during the typical SAGD production stage. The injector well 17 is typically located about 4 to 6 meters above the producer well 15 to define an inter-well region therebetween, however, other relative distances between the wells are possible. The one or more SAGD well-pairs 15, 17 are drilled vertically into the overburden 12 towards and into the underlying pay 10, and as they are drilled become oriented substantially horizontal, such that the producer well 15 is above but near the formation underlying the pay 10. The one or more SAGD well pairs 15, 17 are operated in the SAGD phase, using surface equipment ¨ omitted from FIG. 3 for clarity.

[0055] To prepare the SAGD production site, the location where the one or more SAGD
well-pairs 15, 17 will be located is determined, for example, by conducting typical computer simulations using geological and reservoir data. The corresponding locations of the production site are then prepared for drilling, including providing infrastructure for water and electricity, as is known in the art. A drilling rig is then installed at the location and drilling commences subject to requisite inspections.

[0056] After drilling the wells 15, 17, the pre-heating phase can commence, even prior to installing the surface production equipment for operating the SAGD well pair 15, 17 in the SAGD
phase (which can include, for example, both a start-up phase and a production phase).

[0057] FIG. 4A provides an enlarged view of a well 16 in which a closed loop fluid heating system is configured. The well 16 can generally be any type of well as discussed above. In the drawing, generally horizontal portion 36 is shortened by a break of indeterminate length for ease of illustration. The well 16 in this example implementation includes long tubing 50 extending down the well 16 and terminating near the toe portion 40. The long tubing 50 in this example includes an insulative layer or material 51 along the generally vertical portion thereof to minimize heat loss through the vertical portion of the long tubing 50. For example, vacuum insulating tubing 51 or an insulative wrapping or insulative layer can be used. The long tubing 50 extends through a length of short tubing 52 that terminates near the heel portion 38 of the well 16 creating an annulus 68 between the inner surface of the short tubing 52 and the outer surface of the long tubing 50. In this example, the short tubing 52 also includes an insulative layer or material 53 along the generally vertical portion thereof, to further minimize heat loss.
Similar to the long tubing 50, vacuum insulated tubing 53 or an insulative wrapping or layer can be used with the short tubing 52. The long tubing 50 and short tubing 52 are used for injecting steam into the injector wells 17. When steam is used during a circulation phase (i.e. for achieving start-up), the steam is injected down the long tubing 50 and returns via the annulus 68 22933944.1 = CA 02932090 2016-06-06 between the long tubing 50 and the short tubing 52 in the configuration shown in FIG. 4A.
Then, when the SAGD production phase begins, steam can be injected in both the long tubing 50 and the short tubing 52 of the injector well 17 to heat the pay 10. It can be appreciated that the long/short tubing configuration shown in FIG. 4A is just one example, and that any tubing or string nested within another tubing or string, that is obstructed, can be utilized to implement a heating system 20 as described herein.

[0058] Regarding producer wells 15, generally, the long tubing 50 and short tubing 52 can also be installed therein, and when steam is used for pre-heating, steam can be injected into both the long tubing 50 and the short tubing 52 of the producer well 15.
During the production phase, the producer wells 15 are used to collect heated bitumen by receiving produced fluids through the slotted liner that extends along the generally horizontal portion 36, which are collected by the long tubing 50 and pumped to surface. It can be appreciated that in other implementations, the produced bitumen is gas lifted to surface. The fluid heating system 20 described herein can therefore be deployed into any well 16 that comprises at least a portion of tubing running along the well 16 and which would benefit from pre-heating.

[0059] Whether the heating system 20 is use in an injector well 17 or a producer well 15, injection tubing, such as the coiled tubing 54 shown in FIG. 4A, can be deployed down and along the long tubing 50 towards the end thereof. In this example, the coiled tubing 54 includes an insulative layer or material 55 to minimize heat loss along the length of the coiled tubing 54.
Similar to the long and short tubing 50, 52, vacuum insulated coil tubing 55 can be used, or an insulative wrapping or layer in or on the coiled tubing 52 can be incorporated. To promote temperature conformance along the generally horizontal length of coiled tubing 54, a number of ports 57 can be spaced along the coiled tubing 54 to divert heated fluid 30 into the long tubing 50 along the generally horizontal portion thereof. The ports 57 can be provided using flow diverters, nozzles or other apertures, openings, etc. The coiled tubing 54 has an open end 56 through which the heated fluid 30 can be pumped. It can be appreciated that the ports 57 minimize or eliminate the creation of a hot spot at the open end 56 since heated fluid 30 circulates along the entire horizontal portion of the long tubing 50. It can also be appreciated that the positioning and number of ports 57 can be varied to control the amount and location of heat application along the generally horizontal portion of the long tubing 50.
It can also be appreciated that while in the examples described herein, the heated fluid 30 is injected using the coiled tubing 54 and returned using the annulus between the coiled tubing 54 and the long 22933944.1 tubing 50, the heated fluid 30 could also be injected using the long tubing 50 and produced using the coiled tubing 54.

[0060] FIG. 4B illustrates an alternative implementation wherein insulative portions 59 are spaced along the generally horizontal portion of the coiled tubing 54, to allow heat dissipation along the portions that are uninsulated. The positioning, number, and size of the insulative portions 59 can also be varied to control the application of heat along the generally horizontal portion of the long tubing 50 to optimize temperature conformance. FIG. 4C
illustrates yet another implementation, in which the coiled tubing 54 is insulated only along the generally vertical portion thereof, to promote additional heating dissipation along the entirety of the generally horizontal portion thereof. Various insulation configurations are therefore possible, for example an option wherein only the coiled tubing 54 is insulated (vertical portion only or entirety), another option where the coiled tubing 54 and at least one of the long and short tubing 50, 52 are insulated, another option wherein the insulative materials in the above options are used in conjunction with the ports 57, etc.

[0061] Since the long tubing 50 is normally also open ended, and to ensure that the heated fluid 30 does not escape into the well 16 or into pay 10, an obstruction mechanism such as a bridge plug 60 (as shown in FIGS. 4A, 4B, and 4C) is deployed at the end of the long tubing 50 to allow the heated fluid 30 to circulate through the annulus 58 created between the inner surface of the long tubing 52 and the outer surface of the coiled tubing 54.
The bridge plug 60 can be deployed in any suitable manner. For example, a bridge plug 60 such as that illustrated in FIG. 4 can be deployed or "landed" by being pushed by a length of tubing until it reaches a desired location near the end of the long tubing 50. Hydraulic fluid can then be pumped down the tubing to activate the piston in the bridge plug, which causes the opposing inclined planes of the bridge plug 60 to move relative to each other to increase the diameter of the bridge plug 60 thus sealing the end of the long tubing 50. When hydraulic fluid reaches a predetermined pressure, the tubing disengages from the bridge plug 60 and can be pulled back up to surface 14. To remove the bridge plug 60, a hook-type tool installed on the end of similar tubing used to deploy the bridge plug 60, can be deployed into the long tubing 50 to hook onto the bridge plug 60, and when attached, can be pulled upwardly to release the bridge plug 60, which allows the bridge plug 60 to be pulled back to surface 14 by recoiling the tubing.

[0062] Other examples of suitable obstruction mechanisms include a bullnose attachment 160 as shown in FIG. 6, which can be punctured while the coiled tubing 54 is place to avoid the need to remove the coiled tubing 54 to unseat the obstruction. A similar obstruction can also be 22933944.1 used, which can be ruptured through the application of hydraulic pressure, after the obstruction is no longer needed. Further examples of suitable obstruction mechanisms include packers that increase in size when water is applied thereto, fluid injected bags that swell to create a seal, sliding sleeves, burst discs, and valves. For sliding sleeves and valves, a control line can be used to allow the mechanism to remain in the long tubing and be controlled remotely. That is, by using a valve or other shut-off mechanism, the mechanism can be closed for pre-heating to create the closed loop for the heated fluid circulation, and opened for a subsequent SAGD
phase.

[0063] As the heated fluid 30 is circulated into the annulus 58, heat 62 is transferred to the pay 10 by conduction through the slotted liner, that is, along the generally horizontal portion 36 of the well 16. When used for pre-heating only, after the pre-heating phase is completed, the coiled tubing 54 and bridge plug 60 can be retrieved from the long tubing 50 to enable the long tubing 50 to be used for injecting steam during the SAGD phase. If the heating system 20 is assembled on a moveable module or skid, the module can be moved to another site where needed.

[0064] The pre-heating process described herein, which uses the heated fluid 30, can at least partially overcome the need to perform, e.g., steam circulation during a start-up phase, before commencing a production phase. In cases where steam circulation is still required, the use of the heated fluid 30 can still reduce the amount of time needed to circulate a well, can allow pre-heating to begin prior to installing the steam injection equipment at the site, and can improve the conformance of the steam chamber that develops during steam circulation.

[0065] The coiled tubing 54 can also remain in, or be placed in the well 16 such that it can be used during any phase or stage in which the well is being operated. That is, in addition to pre-heating, the heating system 20 can be used to introduce or enhance heating or improve heating efficiency, including a subsequent start-up or production phase. For example, the heating system 20 can be used while another fluid is being injected into an injector well 17 during a solvent or steam-based production process as shown in FIG. 5A. It can be appreciated that the heating system 20 can be used in a producer well 15, an injector well 17 or both and, in general, any well 16; during any stage of the process as herein exemplified.
FIG. 5A illustrates the same configuration shown in FIGS. 4A-4C, but specifically depicts how the fluid heating system can be utilized in an injector well during a hydrocarbon production phase. An injected fluid 70 is injected through the annulus 68 between the long tubing 50 and the short tubing 52 of an injector well 17 (or any well 16 into which a fluid is injected for production), while heated fluid 22933944.1 30 continues to be circulated in the annulus 58 between the long tubing 50 and the coiled tubing 54. In this configuration, it can be seen that the bridge plug 60 or other obstruction mechanism remains deployed in the injector well 17 during the hydrocarbon production phase. In this way, the heated fluid 30 can be used during a solvent-based or steam-based (e.g.
SAGD) production phase to heat up the injected fluid 70. For example, the heated fluid 30 can be used to heat up a liquid, turn a liquid into vapour, decompose a chemical solution, activate a chemical reaction, maintain steam quality along the liner, and can be used to superheat steam in the liner. While steam or solvent would not be injected down the long tubing 50 during the production phase while the fluid heating system 20 is intact, the steam or solvent that is injected using the short tubing 52 would benefit from the additional heat introduced using the heated fluid 30 (e.g., improve solvent quality). Keeping the fluid heating system 20 in the injector well 17 as shown in FIG. 5A can also minimize the use or intensity of heating equipment at surface 14, thus potentially reducing the surface footprint and the cost.

[0066] In a two well configuration like that shown in FIG. 3, the coiled tubing 54 and obstruction 60 can remain in the long tubing 50 of the injector well 17 as shown in FIG. 5A, with the short tubing 52 used to inject the solvent, steam, etc. during a post pre-heat, startup, and/or production phase. For the producer well 15, when space is needed to accommodate a pump downhole or artificial lift mechanism (e.g., gas lift) to initiate a hydrocarbon production phase of operation, the coiled tubing 54 and obstruction 60 can be removed to "open"
the system 20.
The pump/artificial lift can then be installed in the long tubing 50 or where needed, to produce fluids to surface and initiate the recovery process. As discussed below, the pump or artificial lift can also be installed in an injector well 17, and can be used in the closed loop configuration, after the closed loop has been opened, or both.

[0067] It can be appreciated that once the system 20 has been removed from a well 16, it can be re-deployed at a later time, if necessary ,in order to return to a heated fluid circulation mode, by recompleting the well (i.e., reinstalling the coiled tubing 54), and closing the long tubing 50. For example, if it is found that the particular well pair 15, 17 is not ready for production or becomes cold due to a planned or unplanned delay, the heating system 20 described herein can be re-deployed or introduced at the particular site.

[0068] Turning now to FIG. 5B, in order to minimize the number of well interventions, a downhole pump 72 or other artificial lift mechanism having a size suitable to fit in the well completion can be used to circulate the heated fluid within the closed loop, along with a surface pump 26, instead of driving circulation using only a surface pump 26. The downhole pump 72 22933944.1 or artificial lift mechanism can also be used when the closed loop is opened, e.g., in a producer well 15 as indicated above. The downhole pump 72 or artificial lift mechanism can be used in implementations that also inject another fluid 70, as well as implementations that do not. With the downhole pump 72 or artificial lift mechanism, a smaller surface pump 26 may be possible and/or may not be required once the well 16 is in full production. In such a configuration, heat transfer fluid returned from the injector well 17 and producer well 15 can be merged and heated together, then diverted to the respective coiled tubings 54 in those wells 15, 17. Having a downhole pump 72 or artificial lift mechanism can contribute to a better heat transfer efficiency and minimize the number of well interventions. In such a configuration, the obstruction 60 that is used in a producer well 15 during a pre-heating phase would be removed, and this can be done by using a rupture disk that is ruptured by pressurizing the system while the downhole pump is in place.

[0069] With the system 20 deployed in both an injector well 17 and a producer well 15, additional fluid can be injected, e.g., "bullheaded" in the any available space in the well 16, e.g., the annular space 68 between the short and long tubing 52, 50, in order to improve the heat transfer efficiency and promote hydraulic communication in the interwell region between the wells 15, 17 in preparation for production (i.e. to achieve start-up), similar to what is shown in FIGS. 5A and 5B. For example, steam bullheading, typically used for a start-up phase in combination with or instead of steam circulation can be adapted for this purpose. Various implementations are possible in this configuration. For example, the fluid can be bullheaded in this way either continuously or intermittently. The fluid can also be injected at any time or after achieving a predetermined desired temperature target. The fluid can be injected warm, or cold wherein the heating system 20 is used to increase the temperature of the bullheaded fluid downhole. The bullheading of such fluid can also be done at only the injector well 17, only the producer well 15, or in both wells 15, 17. That is, the fluid heating system 20 can be used for both pre-heating (as described above), or during a start-up-like phase in combination with another fluid, or at any stage in which the wells 15, 16, 17 are being used.
It can be appreciated that the system 20 can be kept as a closed loop system at all times, or can be removed or opened at any time to enable the long tubing 50 to be used to increase the volume of fluid injected into the injector well 17 or producer well 15. The system 20 can be closed again if desired and the heated fluid circulation resume accordingly.

[0070] The heat transfer fluid 30 can be the same or different to the fluid that is bullheaded in the way discussed above. The bullheaded fluid can be a hydrocarbon, produced emulsion, 22933944.1 water, etc.; with viscosity reduction agents, surfactants, nanoparticles, foaming agents, non-condensable gas (to act as a pushing agent to accelerate well communication), etc.

[0071] FIG. 7 illustrates a process for arranging the fluid heating system 20 for pre-heating a well 16. The bridge plug 60 (or other obstruction) is deployed in the long tubing 50 at step 100. The coiled tubing 54 is landed behind the bridge plug 60 at step 102, such that a stream of heated fluid 30 can be fed into the annulus 58 via the open end 56. The coiled tubing 54 is coupled to the fluid heating system 20 at step 104, in order to implement the pre-heating phase illustrated in FIG. 8.

[0072] Turning now to FIG. 8 an example of a pre-heating phase process is shown. The fluid heating system 20 is set up and the coiled tubing 54 deployed at step 110 (e.g., as shown in FIG. 7). The fluid heating system 20 operates, in this example, by having the heaters 24 obtain or otherwise draw fluid from the fluid supply 22 at step 112 and heat the fluid at step 114.
The heated fluid 30 is then pumped down the coiled tubing 54 using the pumps 26 at step 116.
The cooled fluid 32 returns via the annulus between the coiled tubing 54 and the long tubing 50 and is pumped to surface 14, e.g., using the pumps 26. The returned fluid can be reheated by the heaters 24 and/or returned to the fluid supply 22 to be recirculated. The process described herein can be at least partially automated and control logic used for that purpose (and/or a human operator) can determine at step 120 whether or not the pre-heating phase is complete.
If not, the process can repeat from steps 112 or 114 to continue pumping heated fluid 30 into the well 16. When the pre-heating has completed, the fluid circulation can be stopped at step 122. It can be appreciated that the stoppage at step 122 can be temporary if the heated fluid 30 is used during the SAGD phase as shown in FIG. 5.

[0073] For simplicity and clarity of illustration, where considered appropriate, reference numerals can be repeated among the figures to indicate corresponding or analogous elements.
In addition, numerous specific details are set forth in order to provide a thorough understanding of the examples described herein. However, it will be understood by those of ordinary skill in the art that the examples described herein can be practiced without these specific details. In other instances, well-known methods, procedures and components have not been described in detail so as not to obscure the examples described herein. Also, the description is not to be considered as limiting the scope of the examples described herein.

[0074] The examples and corresponding diagrams used herein are for illustrative purposes only. Different configurations and terminology can be used without departing from the principles 22933944.1 expressed herein. For instance, components and modules can be added, deleted, modified, or arranged with differing connections without departing from these principles.

[0075] The steps or operations in the flow charts and diagrams described herein are just for example. There can be many variations to these steps or operations without departing from the principles discussed above. For instance, the steps can be performed in a differing order, or steps can be added, deleted, or modified.

[0076] Although the above principles have been described with reference to certain specific examples, various modifications thereof will be apparent to those skilled in the art as outlined in the appended claims.

22933944.1

Claims (100)

Claims:

1. A method for heating a bitumen or heavy oil reservoir comprising:
circulating heated liquid phase heat transfer fluid within a well in the reservoir, wherein a second tubing is landed in a first tubing located within the well, the first tubing extending beyond the second tubing and being blocked at a distal end downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing, wherein the second tubing is insulated with at least one portion thereof that is uninsulated.

2. The method of claim 1, wherein insulation is provided selectively along a generally horizontal portion of the second tubing.

3. The method of claim 1, wherein insulation is provided along only a generally vertical portion of the second tubing.

4. The method of claim 1, wherein the insulation is provided along the entire length of the second tubing, with a plurality of ports provided along a generally horizontal portion of the second tubing to provide the at least one portion thereof that is uninsulated.

5. The method of any one of claims 1 to 4, wherein the heat transfer fluid heats an interwell region between the well and another well, spaced vertically therefrom.

6. The method of claim 5, wherein the well is an injector well and the other well is a producer well positioned below the injector well.

7. The method of claim 6, wherein heated liquid phase heat transfer fluid is also circulated in the producer well.

8. The method of any one of claims 1 to 7, further comprising deploying an obstruction mechanism into the first tubing prior to circulating the heat transfer fluid to block the first tubing downstream of the second tubing.

9. The method of claim 8, wherein the obstruction mechanism comprises a bridge plug in the first tubing, or a rupture disk or bullnose attachment on an open end of the first tubing.

10. The method of any one of claims 1 to 9, further comprising unblocking the first tubing when preheating has completed.

11. The method of any one of claims 1 to 10, wherein the heat transfer fluid is formulated from a base oil to resist oxidation and increases in viscosity.

12. The method of any one of claims 1 to 11, wherein the heat transfer fluid exhibits a consistent heat capacity over a range of temperatures used during circulation.

13. The method of any one of claims 1 to 12, wherein the heat transfer fluid is heated to a temperature of 250 degrees Celsius or greater.

14. The method of any one of claims 1 to 13, further comprising continuing to circulate the heat transfer fluid in the well during a production phase.

15. The method of any one of claims 1 to 13, further comprising removing the second tubing from the first tubing after completion of the circulating.

16. The method of claim 15, wherein a fluid heating system used to heat the heat transfer fluid is assembled on a movable module located at a first site near the well, the method further comprising moving the movable module to a second site comprising at least one other well.

17. The method of any one of claims 1 to 16, further comprising heating a fluid supply containing the heat transfer fluid.

18. The method of any one of claims 1 to 17, wherein the circulating comprises pumping the heat transfer fluid into the second tubing.

19. The method of claim 18, wherein the circulating comprises pumping cooled heat transfer fluid back to surface.

20. The method of any one of claims 1 to 19, wherein the second tubing comprises coiled tubing.

21. The method of any one of claims 1 to 20, further comprising circulating the heat transfer fluid in first tubing in at least one other well.

22. The method of any one of claims 1 to 21, wherein the well is used for a steam assisted gravity drainage (SAGD) bitumen recovery process, and wherein the first tubing corresponds to long tubing.

23. The method of claim 22, wherein the well is an injector well configured to inject steam into the bitumen reservoir using at least the long tubing.

24. The method of claim 23, wherein the well is a producer well configured to recover mobilized bitumen from the bitumen reservoir using at least the long tubing.

25. The method of any one of claims 1 to 24, further comprising reheating cooled heat transfer fluid circulated to surface and repeating the method using at least a portion of reheated heat transfer fluid.

26. The method of any one of claims 1 to 25, wherein the heat transfer fluid is circulated before, during, or instead of circulating steam in a start-up phase to achieve fluid communication in an interwell region between the well and another well.

27. The method of any one of claims 1 to 26, further comprising injecting an additional fluid into the well while the heat transfer fluid is being circulated.

28. The method of claim 27, wherein the additional fluid is the same as the heat transfer fluid.

29. The method of claim 27, wherein the additional fluid is different than the heat transfer fluid.

30. The method of any one of claims 27 to 29, wherein the additional fluid is injected during a pre-heating phase.

31. The method of any one of claims 27 to 30, wherein the additional fluid is injected during a production phase.

32. The method of any one of claims 27 to 31, wherein the additional fluid is steam or water and the well is an injector well or a producer well.

33. The method of any one of claims 27 to 32, wherein the additional fluid comprises one or more solvents.

34. The method of any one of claims 27 to 33, wherein the additional fluid is injected during a start-up phase.

35. The method of any one of claims 1 to 34, wherein the heat transfer fluid is circulated at least in part using a pump or artificial lift mechanism installed in the first tubing.

36. The method of claim 35, wherein the pump or artificial lift mechanism installed in the first tubing operates with a surface pump.

37. The method of any one of claims 1 to 36, wherein a vertical portion of the first tubing is insulated.

38. The method of claim 1, wherein the well is any one of a vertical well, an infill well, a step-out well, a multilateral well, or a branched well.

39. The method of claim 1, wherein the heated fluid is circulated to inhibit or reduce formation of hydrates or wax, or both, in the well.

40. A method for heating a bitumen or heavy oil reservoir comprising:
circulating heated liquid phase heat transfer fluid within a well in the reservoir, wherein a second tubing is landed in a first tubing located within the well, the first tubing extending beyond the second tubing and being blocked at a distal end downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing; and subsequently injecting an additional fluid into the bitumen reservoir via the well containing the first and second tubing, while continuing to circulate the heat transfer fluid.

41. The method of claim 40, wherein the additional fluid is injected through an annulus in the well that at least in part surrounds the first tubing.

42. The method of claim 40 or claim 41, wherein the heat transfer fluid is injected during a pre-heating phase.

43. The method of claim 42, wherein the additional fluid is injected during a start-up phase subsequent to the pre-heating phase.

44. The method of claim 43, wherein the additional fluid comprises steam.

45. The method of any one of claims 40 to 44, wherein the additional fluid is injected during a production phase.

46. The method of claim 45, wherein the additional fluid is steam or water and the well is an injector well.

47. The method of any one of claims 40 to 46, wherein the additional fluid is injected intermittently.

48. The method of any one of claims 40 to 47, wherein the additional fluid is the same as the heat transfer fluid.

49. The method of any one of claims 40 to 47, wherein the additional fluid is different than the heat transfer fluid.

50. The method of claim 40, wherein the well is any one of a vertical well, an infill well, a step-out well, a multilateral well, or a branched well.

51. The method of claim 40, wherein the heated fluid is circulated to inhibit or reduce formation of hydrates or wax, or both, in the well.

52. A method for heating an interwell region between a first well positioned above a second well in a bitumen or heavy oil reservoir comprising:
circulating heated liquid phase heat transfer fluid within at least one of the first and second wells in the reservoir, wherein a second tubing is landed in a first tubing located within the at least one of the wells, the first tubing extending beyond the second tubing and being blocked at a distal end downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing, wherein the second tubing is insulated with at least one portion thereof that is uninsulated.

53. The method of claim 52, wherein heat transfer fluid is circulated within both the first and second wells.

54. The method of claim 52 or claim 53, wherein the interwell region is heated to achieve fluid communication between the first and second wells.

55. The method of claim 52 or claim 53, further comprising subsequently injecting steam into the bitumen reservoir to achieve fluid communication between the first and second wells.

56. The method of any one of claims 52 to 55, further comprising entering a production phase in which bitumen is produced using the second well.

57. The method of claim 56, wherein the production phase comprises injecting steam into the bitumen reservoir using the first well.

58. The method of claim 57, wherein the production phase comprises a steam assisted gravity drainage (SAGD) bitumen recovery process.

59. The method of claim 56, wherein the production phase comprises injecting solvent into the bitumen reservoir using the first well.

60. The method of any one of claims 56 to 59, wherein the heat transfer fluid continues to be circulated during at least a portion of the production phase.

61. The method of any one of claims 56 to 59, wherein the first tubing is unblocked and the second tubing is removed prior to the production phase.

62. A system for heating a bitumen or heavy oil reservoir comprising:
a source of heated liquid phase heat transfer fluid;
a first tubing located within a well;
a second tubing landed in the first tubing, the first tubing extending beyond the second tubing; and an obstruction mechanism deployed at a distal end of the first tubing downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing, wherein the second tubing is insulated with at least one portion thereof that is uninsulated.

63. The system of claim 62, wherein tho insulation is provided selectively along a generally horizontal portion of the second tubing.

64. The system of claim 62, wherein insulation is provided along only a generally vertical portion of the second tubing.

65. The system of claim 62, wherein the insulation is provided along the entire length of the second tubing, with a plurality of ports provided along a generally horizontal portion of the second tubing to provide the at least one portion thereof that is uninsulated.

66. The system of any one of claims 62 to 65, wherein the heat transfer fluid heats an interwell region between the well and another well, spaced vertically therefrom.

67. The system of claim 66, wherein the well is an injector well and the other well is a producer well positioned below the injector well.

68. The system of claim 67, wherein heated liquid phase heat transfer fluid is also circulated in the producer well.

69. The system of claim 62, wherein the obstruction mechanism comprises a bridge plug deployed into the first tubing prior to circulating the heat transfer fluid, or a rupture disk or bullnose attachment on an open end of the first tubing, to block the first tubing downstream of the second tubing.

70. The system of any one of claims 62 to 69, further comprising at least one pump for circulating the heated liquid phase heat transfer fluid in the well.

71. The system of any one of claims 62 to 70, further comprising at least one heater for heating a source of the heat transfer fluid.

72. The system of claim 71, further comprising the source of heat transfer fluid.

73. The system of claim 72, wherein the source of heat transfer fluid is contained in an expansion tank.

74. The system of any one of claims 62 to 73, wherein the heat transfer fluid is formulated from a base oil to resist oxidation and increases in viscosity.

75. The system of any one of claims 62 to 74, wherein the heat transfer fluid exhibits a consistent heat capacity over a range of temperatures used during circulation.

76. The system of any one of claims 62 to 75, wherein the heat transfer fluid is heated to a temperature of 250 degrees Celsius or greater.

77. The system of any one of claims 62 to 76, wherein the system is assembled on a movable module.

78. The system of any one of claims 62 to 77, further comprising at least one pump for pumping cooled heat transfer fluid back to surface.

79. The system of any one of claims 62 to 78, wherein the second tubing comprises coiled tubing.

80. The system of any one of claims 62 to 79, further comprising additional tubing for circulating the heat transfer fluid in first tubing of at least one other well.

81. The system of any one of claims 62 to 80, wherein the well is used for a steam assisted gravity drainage (SAGD) bitumen recovery process, and wherein the first tubing corresponds to long tubing.

82. The system of claim 81, wherein the well is an injector well configured to inject steam into the bitumen reservoir using at least the long tubing.

83. The system of claim 82, wherein the well is a producer well configured to recover mobilized bitumen from the bitumen reservoir using at least the long tubing.

84. The system of any one of claims 62 to 83, wherein the system is configured to reheat tooled heat transfer fluid circulated to surface and utilize at least a portion of reheated heat transfer fluid.

85. The system of any one of claims 62'to 84, wherein the heat transfer fluid is circulated before, during, or instead of circulating steam in a start-up phase to achieve fluid communication in an interwell region between the well and another well.

86. The system of any one of claims 62 to 85, further comprising equipment for injecting an additional fluid into the well while the heat transfer fluid is being circulated.

87. The system of claim 86, wherein the additional fluid is the same as the heat transfer fluid.

88. The system of claim 86, wherein the additional fluid is different than the heat transfer fluid.

89. The system of any one of claims 86 to 88, wherein the additional fluid is injected during a pre-heating phase.

90. The system of any one of claims 86 to 89, wherein the additional fluid is injected during a production phase.

91. The system of any one of claims 86 to 90, wherein the additional fluid is steam or water and the well is an injector well or a producer well.

92. The system of any one of claims 86 to 91, wherein the additional fluid comprises one or more solvents.

93. The system of any one of claims 86 to 92, wherein the additional fluid is injected during a start-up phase.

94. The system of any one of claims 62 to 93, wherein the heat transfer fluid is circulated at least in part using a pump or artificial lift mechanism installed in the first tubing.

95. The system of claim 94, wherein the pump or artificial lift mechanism installed in the first tubing operates with a surface pump.

96. The system of any one of claims 62 to 95, wherein a vertical portion of the first tubing is insulated.

97. The system of claim 62, wherein the well is any one of a vertical well, an infill well, a step-out well, a multilateral well, or a branched well.

98. The system of claim 62, wherein the heated fluid is circulated to inhibit or reduce formation of hydrates or wax, or both, in the well.

99. A system for heating a bitumen or heavy oil reservoir comprising:
a source of heated liquid phase heat transfer fluid;
a first tubing located within a well;
a second tubing landed in the first tubing, the first tubing extending beyond the second tubing;

an obstruction mechanism deployed at a distal end of the first tubing downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing; and equipment for subsequently injecting an additional fluid into the bitumen reservoir via the well containing the first and second tubing, while continuing to circulate the heat transfer fluid.

100. A system for heating an interwell region between a first well positioned above a second well in a bitumen or heavy oil reservoir comprising:
a source of heated liquid phase heat transfer fluid;
a first tubing located within at least one of the first and second wells;
a second tubing landed in the first tubing, the first tubing extending beyond the second tubing, wherein the second tubing is insulated with at least one portion thereof that is uninsulated;
an obstruction mechanism deployed at a distal end of the first tubing downstream of the second tubing to contain the heat transfer fluid within the first tubing when the heat transfer fluid is circulated down the second tubing and returned to surface up the first tubing; and equipment for injecting an additional fluid into the bitumen reservoir via the well while circulating the heat transfer fluid.